The present invention relates to hydrotreatment of hydrocarbon fractions, for example middle distillates, to produce hydrocarbon fractions with a low sulphur, nitrogen and aromatic compound content particularly for use in the field of internal combustion engine fuels. These hydrocarbon fractions include jet fuel, diesel fuel, kerosine and gas oils. More particularly, the invention relates to the production of a fuel for a compression ignition engine. In this field, the invention relates to a process for transforming a middle distillate and more particularly a gas oil cut to produce a dearomatised and desulphurised fuel with a high cetane number.
Currently, gas oil cuts, whether derived from straight run distillation of a crude or from a catalytic cracking process, still contain non-negligible quantities of aromatic compounds, nitrogen-containing compounds and sulphur-containing compounds. The current legislation of the majority of industrialised countries requires that the fuel for use in engines must contain a quantity of sulphur of less than about 500 parts per million by weight (ppm). In the vast majority of these countries, there are no current regulations imposing a maximum content for aromatic compounds and for nitrogen. However, a few countries or states, like Sweden and California, are envisaging limiting the aromatics content to a value of less than 20% by volume or even less than 10% by volume, and some experts even believe that this content could be limited to 5% by volume. In Sweden in particular, some classes of diesel fuel already have to comply with very strict specifications. Thus in that country, class II diesel fuel must not contain more than 50 ppm of sulphur and more than 10% by volume of aromatic compounds, and class I diesel must not contain more than 10 ppm of sulphur and 5% by volume of aromatic compounds. In Sweden at the moment, class III diesel fuel must contain less than 500 ppm of sulphur and less than 25% by volume of aromatic compounds. Similar limits are also in force for the sale of that type of fuel in California.
Meanwhile, motorists in a number of countries have been pressing for legislation obliging refiners to produce and sell a fuel with a cetane number of a minimum value. Current French legislation requires a minimum cetane number of 49, but in the near future this minimum value will be at least 50 (as is already the case for class I fuel in Sweden), probably at least 55, and most probably 55 to 65.
A number of specialists seriously envisage the future possibility of having a standard imposed on the nitrogen content of less than about 200 ppm, for example, and quite possibly less than 100 ppm. A low nitrogen content can result in better stability of the products and will be of general interest both to the vendor and to the manufacturer.
Thus it is necessary to develop a reliable and effective process for producing a product with improved characteristics both as regards the cetane number and as regards the aromatic compound, sulphur and nitrogen contents from conventional straight run gas oil cuts or from catalytically cracked gas oil cuts (LCO cut) or from another conversion process (coking, visbreaking, residue hydroconversion, etc.). It is particularly important, and this constitutes one of the advantages of the process of the present invention, to produce a minimum of gaseous hydrocarbon compounds so as to obtain an effluent which is directly and integrally useable as a very high quality fuel cut. Further, the process of the present invention can allow production over a long period and without the need for regenerating the catalysts used, which has the advantage of being stable over time. Further, in one implementation of the invention a further advantage resides in the hydrogen recycle. In this implementation, only a fraction of the hydrogen-containing gas is sent to a drying-desulphurising zone before being recycled, enabling the size of the dryer-desulphuriser to be reduced along with the quantity of material required to carry out this operation. In a further variation of the invention, the unit start-up is facilitated when using a furnace to adjust the temperature of the feed entering the second reactor.
U.S. Pat. No. 5,114,562 describes a process for hydrotreating a middle distillate in at least two consecutive steps to produce desulphurised and dearomatised hydrocarbon cuts, comprising a first hydrodesulphurisation step from which the effluent is sent to a hydrogen stripping zone to eliminate the hydrogen sulphide it contains, then the desulphurised liquid fraction obtained is sent to a second, hydrogenation, zone comprising at least two reactors operating in series in which the aromatic compounds are hydrogenated. In this disclosure, the hydrogen used in the stripping zone is makeup hydrogen which has to be added to the process, and after condensation by cooling, the hydrocarbon compounds entrained during stripping are re-introduced into the first hydrodesulphurisation step. The gas separated from the hydrocarbon compounds in the condensation step is treated by washing with an amine solution to eliminate the hydrogen sulphide it contains and is then sent to the second, hydrogenation, zone, then the effluent leaving the hydrogenation zone is separated into a desired liquid fraction and a gaseous fraction which is sent as a mixture with fresh feed to the inlet to the first hydrodesulphurisation step. This mode of operating has a number of disadvantages. Thus the hydrocarbons entrained at the head of the stripper, which are light compounds and which are recycled to the hydrodesulphurisation step, vaporise in this step and thus cause a reduction in the partial pressure of the hydrogen which is not favourable to good hydrodesulphurisation. A further disadvantage is the necessity of having a recycling pump which increases the cost of the equipment and the running costs.
U.S. Pat. No. 5,110,444 describes a process comprising hydrotreatment of a middle distillate in at least three distinct steps. The effluent from the first hydrodesulphurisation step is sent to a hydrogen stripping zone to eliminate the hydrogen sulphide it contains, then the desulphurised liquid fraction obtained is sent to a first hydrogenation zone the effluent from which is sent to a second stripping zone which is distinct from the stripping zone following the hydrodesulphurisation zone. Finally, the liquid portion from the second stripping zone is sent to a second hydrogenation zone. The light hydrocarbons entrained overhead from the first hydrogen stripper are recycled to the hydrodesulphurisation step which is deleterious to the efficiency of this step since in vaporising, these compounds reduce the partial pressure of the hydrogen. Further, this recycling involves the obligatory use of a recycling compressor which increases the equipment costs and the running costs.
The present invention presents a solution which can largely overcome the disadvantages of prior art processes. However, the disclosure of the prior art and in particular that of the documents cited in the text of the present invention form an integral part of the knowledge of the skilled person and all of the features must be considered to be included in the present description.
In its broadest scope, the present invention thus concerns a process for hydrotreating a hydrocarbon fraction such as a middle distillate, and in particular for transforming a gas oil cut to produce a high cetane number, dearomatised and desulphurised fuel in at least two successive steps. It also concerns the fuel obtained by said process. In the present description, the term xe2x80x9cmiddle distillatexe2x80x9d designates hydrocarbon fractions boiling in the range about 130xc2x0 C. to about 385xc2x0 C., normally in the range about 140xc2x0 C. to about 375xc2x0 C. and usually in the range about 150xc2x0 C. to about 370xc2x0 C., determined using the appropriate ASTM method. The process of the present invention is also of application in the treatment of hydrocarbon fractions with a boiling point in the naphtha range. This process can be used to produce hydrocarbon cuts for use as a solvent, as an additive or as fuels preferably with a reduced aromatic compound content. The term xe2x80x9ckerosinexe2x80x9d as used in the present invention designates a hydrocarbon fraction boiling in the range 130xc2x0 C. to 250xc2x0 C. The term xe2x80x9cdiesel fuelxe2x80x9d as used in the present description means a hydrocarbon fraction boiling in the range 230xc2x0 C. to 385xc2x0 C. The term xe2x80x9cnaphthaxe2x80x9d as used in the present description designates a hydrocarbon fraction from C5 to the endpoint of about 210xc2x0 C. The term xe2x80x9cgas oilxe2x80x9d as used in the present description designates a hydrocarbon fraction boiling in the range 230xc2x0 C. to 420xc2x0 C. or heavier fractions boiling in the range 420xc2x0 C. to 525xc2x0 C. The term xe2x80x9cjet fuelxe2x80x9d as used in the present description designates a hydrocarbon fraction boiling in the range 130xc2x0 C. to 290xc2x0 C. The hydrocarbon fraction which is preferably used in the present process is a fraction with an initial boiling point of more than about 150xc2x0 C. and with a boiling point for 90% of the distilled fraction, which is usually less than about 370xc2x0 C. This fraction normally contains nitrogen in the form of organonitrogen compounds in a quantity which is usually about 1 ppm to about 1% by weight. It also contains sulphur in the form of sulphur-containing organic compounds in a quantity which is normally more than about 0.1% by weight and usually about 0.15% to about 5% by weight, usually about 0.5% to about 3.5% by weight. The amount of mono and/or polynuclear aromatic compounds is normally more than 10% by volume and usually more than 20% by volume, normally less than about 60% by volume and usually less than about 50% by volume.
More precisely, the present invention provides a process for hydrotreating a hydrocarbon feed containing sulphur-containing compounds, nitrogen-containing compounds and aromatic compounds, comprising the following steps:
a) at least one first step in which said feed and hydrogen are passed into a hydrodesulphurisation zone containing at least one hydrodesulphurisation catalyst comprising, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table and at least one metal or compound of a metal from group VIII of said periodic table, said zone being maintained under hydrodesulphurisation conditions including a temperature of about 260xc2x0 C. to about 450xc2x0 C. and a pressure of about 2 MPa to about 20 MPa;
b) at least one second step in which the partially desulphurised feed from the first hydrodesulphurisation step is sent to a stripping zone in which it is purified by stripping with a counter-current of at least one gas containing hydrogen at a pressure substantially identical to that prevailing in the first step and at a temperature of about 100xc2x0 C. to about 350xc2x0 C. under conditions for formation of a gaseous stripping effluent containing hydrogen and hydrogen sulphide and a liquid effluent containing substantially no more hydrogen sulphide;
c) at least one third step in which, after adding substantially pure makeup hydrogen and usually recycled hydrogen, the liquid feed from the stripping step is sent to a hydrotreatment zone containing a hydrotreatment catalyst comprising, on a mineral support, at least one noble metal or compound of a noble metal, preferably from group VIII. After bringing it to a temperature of about 220xc2x0 C. to about 360xc2x0 C. and a pressure of about 2 MPa to about 20 MPa in said zone by direct heat exchange, this effluent is maintained under hydrotreatment conditions to obtain a partially dearomatised effluent; said process being characterized in that the gaseous effluent formed in the stripping step, containing hydrocarbons which are gaseous under the conditions in said stripping zone, hydrogen and hydrogen sulphide, is cooled to a temperature which is sufficient to form a liquid hydrocarbon fraction which is sent to the stripping zone, and a gaseous fraction which is depleted in hydrocarbons which is sent to a zone for eliminating the hydrogen sulphide it contains and from which purified hydrogen is recovered.
The present invention also concerns the partially desulphurised and partially dearomatised hydrocarbon fraction obtained using the process of the invention.
A variety of implementations of the present invention can be realised, either separately from each other or in combinations. In an advantageous implementation, the stripping gas is a fraction of the makeup hydrogen used in the process of the invention. This fraction of makeup hydrogen normally represents less than 90% by volume of the total volume of makeup hydrogen used in the process, usually less than 60% and more usually about 1% to about 50%.
In a particular implementation of the invention, at least a portion of purified hydrogen recovered from the zone for eliminating hydrogen sulphide contained in the gaseous fraction depleted in hydrocarbons obtained from the stripping zone is sent to a drying-desulphurising zone from which substantially pure and substantially dry hydrogen is recovered, and the other portion is recovered without complementary treatment.
The hydrogen from a gaseous mixture containing hydrogen and hydrogen sulphide from the stripping zone is normally purified using one or other of the conventional techniques which are well known to the skilled person and in particular by a prior treatment of this gaseous mixture with a solution of at least one amine under conditions which can eliminate hydrogen sulphide by absorption, said amine usually being selected from the group formed by monoethanolamine, diethanolamine, diglycolamine, diusopropylamine and methyldiethanolamine. In a particular implementation of this absorption, the gaseous mixture is brought into contact with a basic solution, preferably an aqueous solution of an amine selected from the group mentioned above, which forms an addition compound with the hydrogen sulphide and which can produce a purified gas containing proportions of hydrogen sulphide which are much lower than 500 ppm by weight and usually less than about 100 ppm by weight.
Usually the quantity of hydrogen sulphide remaining is less than about 50 ppm by weight and more usually less than about 10 ppm by weight. This method for purifying a gaseous mixture is a conventional method which is well known to the skilled person and which has been widely described in the literature. It has, for example, been succinctly described for treating natural gas containing hydrogen sulphide in Ullmann""s Encyclopaedia volume A12 pages 258 ff. In the present invention, the treatment with an aqueous diamine solution is normally carried out at a temperature of about 10xc2x0 C. to about 100xc2x0 C. and usually about 20xc2x0 C. to about 70xc2x0 C. The quantity of amine used is normally such that the hydrogen sulphide to amine mole ratio is about 0.11:1 to about 1:1 and usually about 0.3:1 to about 0.8:1, for example about 0.5:1. The pressure at which the hydrogen sulphide is absorbed by the amine solution is normally about 0.1 MPa to about 50 MPa, usually about 1 MPa to about 25 MPa and usually about 1 MPa to about 10 MPa. The amine solution is conventionally regenerated by varying the pressure. To obtain a dryer gas and better elimination of the hydrogen sulphide initially present in the gaseous mixture, it is also possible to carry out a complementary treatment on at least a portion of this gaseous mixture, such as treating the gas leaving the absorption step in a hydrogen sulphide adsorption zone comprising at least one reactor and normally at least two adsorption reactors containing a sieve, for example, preferably a regeneratable sieve or, for example, zinc oxide, and operating, for example, at a temperature of about 10xc2x0 C. to about 400xc2x0 C., normally about 10xc2x0 C. to about 100xc2x0 C. and usually about 20xc2x0 C. to about 50xc2x0 C. at a total pressure of about 0.1 MPa to about 50 MPa, usually about 1 MPa to about 25 MPa and preferably about 1 MPa to about 10 MPa. In this implementation, when the adsorption zone comprises two reactors, one reactor is used to treat the gas while the other is being regenerated or the material it contains is being replaced, to dry and desulphurise the gaseous mixture entering said zone. At the outlet from this complementary treatment, the hydrogen sulphide content of the gas is normally less than 1 ppm by weight and usually of the order of a few tens of ppb by weight.
In one implementation, the gaseous effluent formed in the stripping step is cooled by at least one cooling means located inside the stripping zone close to the outlet for said gaseous effluent from said stripping zone.
In a further advantageous implementation, the.gaseous effluent formed in the stripping step is cooled by at least one cooling means located outside the stripping zone and is at least partially condensed, at least a portion of the liquid obtained being returned to the stripping zone.
In a further implementation, the gaseous effluent formed in the stripping step is cooled by at least one cooling means, at least a portion of the liquid hydrocarbon fraction obtained being returned to the stripping zone and optionally at least a further portion being sent to hydrodesulphurisation step a) as a mixture with the hydrocarbon feed.
The substantially pure hydrogen recovered after the stripping step is recycled to the stripping zone to at least one introduction point located between the point for introducing a portion of the gas containing hydrogen used for stripping and the point for introducing effluent from hydrodesulphurisation step a) into said stripping zone.
The substantially pure hydrogen recovered after the stripping step is recycled directly, and/or after mixing with the feed, to the hydrodesulphurisation zone of step a).
The substantially pure hydrogen recovered after the stripping step, preferably already dried and deeply desulphurised, is recycled to the hydrotreatment zone of step c) directly and/or after mixing with the liquid effluent from the stripping zone and with the makeup hydrogen.
In a particular implementation of the process of the invention, if it is not wished to dry the whole of the substantially pure hydrogen recovered from the hydrogen sulphide elimination zone, it is advantageous to carry out drying and deep desulphurisation of the hydrogen which is to be recycled to hydrotreatment step c).
In a preferred implementation of the invention, the operating conditions of steps a) and c) are selected as a function of the characteristics of the feed which may be a straight run gas oil, a gas oil cut originating from catalytic cracking or a gas oil from coking or visbreaking of residues or a mixture of two or more of these cuts. They are normally selected so as to obtain a product at the outlet from step a) containing less than 100 ppm of sulphur and less than 200 ppm of nitrogen, preferably less than 100 ppm of nitrogen and usually less than 50 ppm of nitrogen and the conditions of step c) are selected so as to produce a product at the outlet from said step c) containing less than 20% by volume of aromatic compounds. These conditions can be made more severe to obtain, after the second step, a fuel containing less than 10% by volume of aromatic compounds or even less than 5% by volume of aromatic compounds, less than 50 ppm or even less than 10 ppm of sulphur, less than 50 ppm or even less than 20 ppm of nitrogen or more preferably less than 10 ppm and with a cetane number of at least 50 or even at least 55 and usually in the range 55 to 60.
To obtain such results, the conditions of step a) comprise a temperature of about 300xc2x0 C. to about 450xc2x0 C., a total pressure of about 2 MPa to about 20 MPa and an overall hourly space velocity of liquid feed of about 0.1 to about 4 and that of step b) is a temperature of about 200xc2x0 C. to about 400xc2x0 C., a total pressure of about 3 MPa to about 15 MPa and an hourly space velocity of liquid feed of about 0.5 to about 10.
The catalyst used in step a) contains, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, normally about 0.5% to 40%, and at least one metal or compound of a metal from group VIII of said periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, normally about 0.1% to 30%. Usually, the catalyst used will contain at least one element selected from the group formed by silicon, phosphorous and boron or compounds of this or these elements. The catalyst will, for example, contain phosphorous or at least one phosphorous compound in a quantity, expressed as the weight of phosphorous pentoxide with respect to the weight of support, of about 0.001% to 20%. The quantity of metal or compound of metal from group VIB, expressed as the weight of metal with respect to the weight of finished catalyst, is preferably about 2% to 30% and usually about 5% to 25%, and that of the metal or metal compound from group VIII will preferably be about 0.5% to 15%, usually about 1% to 10%.
When a relatively low temperature range is desired but excellent results are to be retained, it is possible to carry out a first step a1) under conditions which can reduce the sulphur content of the product to a value of about 500 to 800 ppm then to send this product to a subsequent step a2) in which the conditions are selected to bring the sulphur content to a value of less than about 100 ppm, preferably less than about 50 ppm, and the product from this step a2) is then sent to step b). In this implementation, the conditions of step a2) are milder than when a single step a) is used for a given feed since the product sent to this step a2) already has a reduced sulphur content. In this type of implementation, the catalyst of step a1) can be a conventional prior art catalyst such as that described in the text of the Applicant""s French patents FR-A-2 197 966 and FR-A-2 538 813 and that of step a2) is that described above for step a). The scope of the present invention also encompasses using the same catalyst in steps a1) and a2).
In these steps a), a1), a2), the mineral support of the catalyst is preferably selected from the group formed by alumina, silica, silica-aluminas, zeolites and mixtures of at least two of these mineral compounds. Alumina is routinely used.
In a preferred implementation of the invention, the catalyst of these steps a), a1), a2) comprises at least one metal or metal compound selected from the group formed by molybdenum and tungsten and at least one metal or compound of a metal selected from the group formed by nickel, cobalt and iron. This catalyst usually contains molybdenum or a molybdenum compound and at least one metal or metal compound selected from the group formed by nickel and cobalt.
In a particular and preferred implementation of the invention, the catalyst in these steps a), a1), a2) comprises boron or at least one boron compound preferably in a quantity, expressed as the weight of boron trioxide with respect to the weight of the support, of about 0 to 10%. Other implementations are also frequently used and in this case, for example, the catalyst comprises a silicon or a silicon compound, or a combination of silicon and boron or compounds of each of these elements, optionally combined with phosphorous or a phosphorous compound. Non limiting examples of specific combinations containing these elements or compounds of these elements which can be cited are: Nixe2x80x94Moxe2x80x94P, Nixe2x80x94Moxe2x80x94Pxe2x80x94B, Nixe2x80x94Moxe2x80x94Si, Nixe2x80x94Moxe2x80x94Sixe2x80x94B, Nixe2x80x94Moxe2x80x94Pxe2x80x94Si, Nixe2x80x94Moxe2x80x94Sixe2x80x94Bxe2x80x94P, Coxe2x80x94Moxe2x80x94P, Coxe2x80x94Moxe2x80x94Pxe2x80x94B, Coxe2x80x94Moxe2x80x94Si, Coxe2x80x94Moxe2x80x94Sixe2x80x94B, Coxe2x80x94Moxe2x80x94Pxe2x80x94Si, Coxe2x80x94Moxe2x80x94Sixe2x80x94Bxe2x80x94P, Nixe2x80x94Wxe2x80x94P, Nixe2x80x94Wxe2x80x94Pxe2x80x94B, Nixe2x80x94Wxe2x80x94Si, Nixe2x80x94Wxe2x80x94Sixe2x80x94B, Nxe2x80x94Wxe2x80x94Pxe2x80x94Si, Nixe2x80x94Wxe2x80x94Sixe2x80x94Bxe2x80x94P, Coxe2x80x94Wxe2x80x94P, Coxe2x80x94Wxe2x80x94Pxe2x80x94B, Coxe2x80x94Wxe2x80x94Si, Coxe2x80x94Wxe2x80x94Sixe2x80x94B, Coxe2x80x94Wxe2x80x94Pxe2x80x94Si, Coxe2x80x94Wxe2x80x94Sixe2x80x94Bxe2x80x94P, Nixe2x80x94Coxe2x80x94Moxe2x80x94P, Nixe2x80x94Coxe2x80x94Moxe2x80x94Pxe2x80x94B, Nixe2x80x94Coxe2x80x94Moxe2x80x94Si, Nixe2x80x94Co-Moxe2x80x94Sixe2x80x94B, Nixe2x80x94Coxe2x80x94Moxe2x80x94Sixe2x80x94P.
The catalyst used in step c) contains, on a mineral support, at least one noble metal or a compound of a noble metal from group VIII of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.01% to 20%, and preferably at least one halogen. The mineral support of the catalyst used in step c) is selected independently of the support used for the catalyst of step a). The catalyst of step c) usually comprises at least one metal or compound of a noble metal selected from the group formed by palladium and platinum.
The mineral support of the catalyst used in step c) is usually selected from the group formed by alumina, silica, silica-aluminas, zeolites and mixtures of at least two of these mineral compounds. This support preferably comprises at least one halogen selected from the group formed by chlorine, fluorine, iodine and bromine, preferably from the group formed by chlorine and fluorine. In an advantageous implementation, this support comprises chlorine and fluorine. The quantity of halogen is usually about 0.5% to 15% by weight with respect to the weight of the support. The support which is most frequently used is alumina. The halogen is normally introduced into the support from the corresponding acid halides and the platinum or palladium from aqueous solutions of their salts or compounds, such as hexachloroplatinic acid in the case of platinum.
The quantity of metal of this catalyst of step c) is preferably about 0.01% to 10%, normally about 0.01% to 5% and usually about 0.03% to 3%, expressed as the weight of metal with respect to the finished catalyst.